Lithofacies heterogeneity in channel sandstones in a labyrinth-type reservoir outcrop are expressed by the nested correlation structure of experimental permeability semivariograms. First-rate correlation lengths are related to average set size or the average thickness of laterally accreted beds, second-rate correlation lengths to the average spacing of cosets or beds, and third-rate correlation lengths to the average spacing of surfaces truncating individual point bars within a meander loop. Three flow units are defined. Flow unit I comprises ribbon sandstone bodies and is characterized by large trough cross-stratified sets. Second-order bounding surfaces are dominant. Permeability is interdependent between two second-order bounding surfaces. Flow unit II comprises the lower part of meander loop sandstone bodies without grain size differences visibly expressed at the lateral accretion surfaces. Lithofacies and permeability characteristics are similar to flow unit I although the average set size and mean permeability are low. The average volume of flow unit II is largest. Flow unit III comprises the heterolithic upper part of meander loop sandstone bodies built up by ripple lamination in laterally accreted beds with distinct grain size changes. The latter form pronounced bounding surfaces and, significantly, determine two-dimensional permeability interdependency. The mean permeability is three times smaller than that of flow unit I. The spatial distribution of the flow units is mainly determined by climatic fluctuations from relatively humid to relatively arid conditions.
Enhanced oil recovery through injection of a solution of water and polymer is becoming a mature chemical flooding technique. In general, reservoirs with mature water-flooding projects offer an excellent opportunity for extension with polymer injection as uncertainties associated with reservoir connectivity and injection potential are already substantially reduced. For our particular reservoir an additional fortunate circumstance includes an ongoing polymer injection project in an adjacent reservoir which enables easy field testing given the local operational challenges and circumstances. This paper presents ongoing work related to improving ultimate oil recovery from an active water flood project by polymer injection where a polymer flooding pilot is already ongoing. The work includes studies to extend the existing polymer injection facilities of a nearby polymer project to this rather different, in geologic terms, Precambrian reservoir with much lower permeability, oil saturations and significantly more layered reservoir architecture. Geological and petrophysical workflows together with dynamic modeling history matching iterations resulted in reducing subsurface uncertainties such as the distribution of permeability and initial oil saturation. Reservoir compartment connectivity and sweep efficiency are constrained by matching pressure and injection, as well as, production data from 180 wells. Polymer injection feasibility is proven through: dynamic modeling, laboratory experiments, ongoing polymer injection pilot and adapting learning’s from the ongoing adjacent polymer project. The study reveals that a polymer injection project is economically feasible under a range of subsurface and costs scenarios.
The field is located onshore Abu Dhabi and has been in production for more than 50 years. It covers an area of approximately 1500 square kilometers and has 20 reservoirs with producible hydrocarbons comprising a series of stacked oil and gas reservoirs with differing drive mechanisms and development maturity, including in-field exploration targets. This paper describes the work undertaken to build a full field Shared Earth Model (SEM) to support future drilling to maximize the field recovery and extend the field lifetime. The key business deliverable for the SEM was to allow more effective assurance of planned well trajectories in a highly congested surface/subsurface environment, thus increasing the safety of such operations. As a consequence, the SEM had to extend from ground level to the deepest penetrated reservoirs. The reservoir model is constrained by more than 70 seismic horizons and by more than 40,000 well markers of various vintages; this alone represented a significant modeling challenge. Automated QC & QA workflows were used heavily to analyse the input data and the model during each of the model construction iterations. The reservoir units are faulted but these faults do not extend to the surface. Due to limitations in the representation of such faults in pillar grids and a lack of continuity of fault interpretations from one reservoir to the next, it was decided to represent faults as properties and not as fault planes. This not only allowed adjustment per reservoir, without requiring a rebuild of the whole structural model, but also identified clearly a zone of uncertainty around the predicted faults, assisting well planning efforts. A major focus of the project was to provide an evergreen model which could be kept up to date with ADCO's substantial drilling program. Therefore considerable effort was made to hand over not just a model, but also training in the key workflow's and work practices which would ensure that ADCO staff have the skills in house to update and maintain the model. This was achieved through extensive use of Petrel workflows, which enabled quick & structured model updates and through several training sessions in Abu Dhabi, run over 3–4 days. This proved to be an effective mechanism to hand over the model and workflows to ADCO staff.
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